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A Technical and Economical Evaluation of CO 2 Capture
from Fluidized Catalytic Cracking (FCC) Flue Gas
Romina Digne, Frédéric Feugnet, Adrien Gomez
To cite this version:
D o s s i e r
Post Combustion CO2Capture Captage de CO2en postcombustion
A Technical and Economical Evaluation
of CO
2
Capture from Fluidized Catalytic Cracking
(FCC) Flue Gas
Romina Digne
*
, Frédéric Feugnet and Adrien Gomez
IFP Energies nouvelles, Rond-point de l'échangeur de Solaize, BP 3, 69360 Solaize - France e-mail: [email protected] - [email protected] - [email protected]
* Corresponding author
Re´sume´ — E´valuation technico-e´conomique du captage du CO2pre´sent dans les fume´es d’une unite´
FCC (Fluidized Catalytic Cracking) — Les contraintes environnementales actuelles relatives aux gaz a` effet de serre et parmi eux le CO2vont devenir des challenges a` relever a` court terme. La
pression sur l’industrie et par conse´quence sur le raffinage afin de limiter et de ge´rer les e´missions de CO2va vraisemblablement se renforcer dans les prochaines anne´es.
L’industrie du raffinage contribue pour 2,7 % aux e´missions totales de CO2. Le craquage
catalytique en lit fluidise´ (FCC) qui est l’un des proce´de´s principaux du raffinage, repre´sente a` lui seul 20 % des e´missions de CO2de la raffinerie. Sachant que ce type d’unite´ est pre´sente
dans une raffinerie sur deux, on comprend bien le de´fi a` trouver des technologies afin d’en ge´rer les e´missions.
Sur la base d’un cas industriel, les objectifs de cette e´tude sont de de´terminer si la technologie HiCapt+, de´veloppe´e pour les centrales e´lectriques, constitue une solution pertinente pour le domaine du raffinage et particulie`rement pour le proce´de´ FCC ainsi que d’e´valuer le couˆt additionnel associe´ qui devra eˆtre supporte´ par les raffineurs.
Abstract — A Technical and Economical Evaluation of CO2 Capture from Fluidized Catalytic
Cracking (FCC) Flue Gas — Environmental issues, related to greenhouse gas and among them CO2, are becoming short term challenges. Pressure on industries and therefore on refining to limit
and manage CO2emissions will be reinforced in next few years.
Refining industry is responsible for about 2.7% of global CO2 emissions. Fluidized Catalytic
Cracking unit (FCC), one of the main process in refining, represents by itself 20% of the refinery CO2emissions. As FCC unit is present in half of the refining schemes, it is challenging to find
tech-nologies to manage its emissions.
Based on an industrial case, the aims of the presented work are to determine if amine technology HiCapt+, developed for power plant, might be a relevant solution to manage FCC CO2emissions
INTRODUCTION
Environmental issues and global warming effect are going to strengthen, in short and mid term, greenhouse gas limitations and among them CO2 emissions. In
Europe, pressure on industries have been reinforced, in the last few years by legislation and the two first stages of European Union Emission Trading System (EU ETS). Currently, the cost of a ton of CO2emission
is quite low (6.5 euros/ton) and this is due to an excess of CO2quotas estimated at around 13%.
Stage three of EU ETS is going to be spread for 2013-2020 period. The main differences of this new stage compared to the previous ones will be a decrease of free quotas by 1.75% per year and an increase of no free CO2
proportion with a final target in 2020 fixed at 70% of total quotas. It means that in 2020, CO2quotas will be
limited by 21% compared to 2005 situation. In this con-text, refiners will have to reduce by around 10% their current CO2 emissions or will have to buy quotas on
CO2market.
As a reminder, refining industry is responsible for about 2.7% of global CO2 emissions. The top five of
most CO2 emitters are the vacuum distillation unit
(10%), the topping tower (15%), the utility production unit (17%), the steam methane reforming (in the range from 10 to 50% depending on refining scheme) and the Fluidized Catalytic Cracking Unit (FCCU) (20%).
In 2013, refining margins in Europe are low (less than 2 dollars per barrel). This new financial constraint related to CO2 will be therefore negatively impact for
refiners. This implies that there is a need for technologi-cal solutions in order to minimize CO2 emissions for
refining processes.
This is especially true for FCCU in the extent that it is one of the main CO2contributors and that coke
produc-tion and combusproduc-tion during regeneraproduc-tion step are required to run the unit. FCC process converts heavy oil fractions to lighter products such as Liquefied Petro-leum Gas (LPG) and gasoline by means of a cracking catalyst. During the reaction step, coke is formed and deposited on the surface of the catalyst, which is then deactivated. To recover catalyst activity, coke is burnt in a regenerator with air and CO2is formed. FCC flue
gas contain about 10-20% mol of CO2for example in full
combustion mode. Heat produced in regeneration sec-tion is transferred through the catalyst in the reacsec-tion section to vaporize the feedstock and to reach the desired riser outlet temperature. The heat balance between regeneration section and reaction section is one of the key points of this process.
The capture of CO2from FCC flue gas is therefore
a good way to reduce GHG emissions in refineries.
Post-combustion technologies such as CO2 absorption
may be used. The objective of this study is to evaluate the CO2capture from flue gas of an industrial FCC unit
with available amine technology HiCapt+TM [1] devel-oped by IFP Energies nouvelles and PROSERNAT. Fea-sibility and costs have been evaluated.
This work has been carried out within the FCC Alli-ance program developed by Total, Technip, Axens and IFP Energies nouvelles.
1 DESCRIPTION OF HICAPT+AMINE PROCESS
FOR CO2CAPTURE
Simplified process flow diagrams of HiCapt+TMprocess for CO2post-combustion capture and CO2compression
are presented inFigure 1andFigure 2.
Flue gas temperature at inlet of HiCapt+TM unit is around 50°C. In conventional schemes, a water quench tower is mandatory to cool down flue gas to 50°C. Flue gas enters the amine capture unit at atmospheric pres-sure. A blower is used to increase the pressure in order to compensate for the pressure drop through the absor-ber and to allow the evacuation of treated gas towards the stack.
Flue gas specifications at inlet of HiCapt+ unit are provided inTable 1.
After the blower, the flue gas is introduced at the bot-tom of the absorber. This column uses a random or struc-tured packing. The lean solvent is introduced at the top of the absorption section. The solvent is an aqueous solution of MonoEthanolAmine (MEA) at 40 wt%. The solvent and the flue gas flows circulate in counter-current manner through the packing. CO2 present in flue gas diffuses
through the solvent and reacts with MEA. The internal packing enhances mass transfer between the gas and liquid to ensure an optimum efficiency of the CO2
cap-ture. The absorption zone and the lean MEA flow rate are designed to reach a 90% CO2capture.
The decarbonised gas continues its rise through the washing section zone of the absorber, also equipped with packing. This section recovers the MEA and other orga-nic compounds in the vapour (thermodynamic and mechanical entrainments) thanks to water washing at the top of the column. This zone reduces the amounts of degradation products and MEA contained in flue gas (volatile organic compounds, mainly NH3, MEA,
etc.). Part of water extracted from washing zone is sent to the main solvent loop in order to keep a neutral water balance.
The decarbonised flue gas from the absorber is relea-sed to the atmosphere. The content of residual MEA is negligible.
The solvent outlet at the bottom of absorber, highly loaded in CO2, is pumped and then preheated in the heat
recovery exchanger, from 60°C to 100°C approximately, by the regenerated solvent coming from the bottom of the stripper (also called regenerator). The preheated sol-vent is introduced into the stripper, at a pressure between 1 and 2 bar approximately. The rich solvent circulates
through the packed column. In the bottom of a regener-ator, a reboiler vaporizes a part of the solvent to provide the thermal energy necessary for regeneration.
The regenerated lean solvent is pumped towards the heat recovery exchanger for the preheating of the rich solvent. The temperature of the lean solvent decreases from 120°C to 70°C approximately. A second heat
Reboiler Absorber Absorption zone Stripper (regenerator) Blower Flue gas Rich amine Condenser Lean amine Decarbonised gas Water CO2 CO2 compression unit CO2 supercritical (110 bar) Reclaimer Degradation products to treatment unit Absorber Washing water zone Figure 1
Simplified process flow diagram of HiCapt+TM[1] process.
exchanger makes it possible to cool the lean solvent to around 50°C before storage and injection in the absor-ber.
The CO2recovered at the top of stripper, containing
steam, is sent towards the condenser. The condensate returns towards the regeneration column and the CO2
flow, with a purity greater than 99.9 mol% (except water content), is then conditioned for its transportation and injection. The conditioning phase needs several stages of compression/condensation and pumping to change CO2into a supercritical state at 110 barg, this pressure
being able to vary according to specificities of each case. Moreover, part of the regenerated solvent resulting from the regeneration column is sent towards a batch boiler. This equipment named “reclaimer” enables the vaporization of the solvent (H2O + MEA) to
concen-trate in an aqueous phase the degradation products (heat stable salt). These by-products are treated by an addi-tional water treatment unit.
The degradation of the solvent is highly limited thanks to the addition of an inhibitor [2] of the reactions due to oxygen. The additive makes it possible to strongly decrease the ammonia emission and to reach the emis-sions specification at lower costs.
2 INDUSTRIAL FCC UNIT 2.1 FCC Unit Description
To evaluate the feasibility of CO2capture from FCC flue
gas, an industrial case has been considered. The FCC unit evaluated in this study is located in Europe with processing capacity of 60 000 BPSD (Barrels Per Stream Day). For this case, FCC feed is an hydrotreated vac-uum gas oil and the unit operates in maximum gasoline mode (gasoline yield around 51% of fresh feed).
An expander is installed on flue gas from the regener-ator. This expander is coupled with the Main Air Blower (MAB). The flue gas at the expander outlet is sent to a waste heat boiler that cools the flue gas and generates a high pressure steam.
The flue gas at waste heat boiler outlet is sent to an ElectroStatic Precipitator (ESP) to reduce particulates content and then vented to the atmosphere trough the stack.
The temperature of the flue gas at the outlet of ESP is around 250°C.
Wet gas or vapors from the main fractionator overhead reflux drum are compressed by the Wet Gas Compressor (WGC). The WGC is a two stage inter-cooled centrifugal machine generally driven by a steam turbine or by an electrical motor. The wet gas compres-sor of the industrial FCC unit considered for this study is driven by an electrical motor.
2.2 FCC Flue Gas Characteristics
The properties of the FCC flue gas are given after heat recovery in a waste heat boiler and after the electrostatic precipitator. This composition is comparable with values provided by [3].
Flue gas properties are presented inTable 2.
Despite the presence of an electrostatic precipitator, the content of particulates in flue gas is too high for HiCapt+TMprocess (Tab. 1,2). Deeper SO2and NOx
removals from FCC flue gas are also required for HiCapt+TMprocess (Tab. 1,2).
2.3 CO2Balance of FCC Unit
A simplified CO2balance of FCC unit (Tab. 3) has been
estimated considering the three main contributors which are:
– coke combustion;
TABLE 2 FCC flue gas characteristics
Pressure 0.04 barg Temperature 250 °C Composition N2 77.5 mol% CO2 17.7 mol% H2O 3.6 mol% O2 1.2 mol% SO2 134 mg/Nm3 NOx 118 mg/Nm3 CO 15 mg/Nm3 Particulates 30 mg/Nm3 TABLE 1
Flue gas specifications for HiCapt+TM
Component Specification SO2 < 10-20 mg/Nm 3 NO2 < 15 mg/Nm 3 NOx < 200 mg/Nm3 Particulates < 10 mg/Nm3
– electricity consumption for wet gas compressor and main air blower;
– steam balance (consumption – production).
3 CO2CAPTURE FROM FCC FLUE GAS WITH HICAPT+TM
AMINE PROCESS
3.1 FCC Flue Gas Pre-Treatment before CO2Capture
SO2 and NOx removal technologies were investigated.
Two different technologies for SO2and NOxremovals,
wet and dry scrubbers, were proposed. In both cases, the temperature of FCC flue gas is 250°C.
3.1.1 Wet Scrubber Technology (Fig. 3)
In this case, the gas treatment consists of dust capture by electrostatic precipitator at 250°C, then a catalytic DeNOx scrubber at 250°C with injection of ammonia
solution (NH4OH) 25 wt%. The DeSOxwashing section
(with caustic soda) reduces the SO2 concentration at
10 mg/Nm3. The DeSOxunit works at low temperature
(about 50°C). This technology is mature. The electrofilter is mandatory according to the wet scrubber supplier.
3.1.2 Dry Scrubber Technology (Fig. 4)
In case dry scrubber is used, an inlet temperature of 200°C is recommended based on the reactant used
TABLE 3
Simplified CO2balance of FCC unit
Value CO2emission factor CO2eq (t/h)
Coke combustion 18.4 t/h 3.4 t CO2eq/t of coke 62.9
Electricity consumption for MAB and WGC 6.1 MW 148 g CO2eq/MJ of electricity(1) 3.3
Steam balance (consumption – production) 47.8 MW 72 g CO2eq/MJ of steam(2) 12.4
Total 53.8
(1)Corresponding to world average (2004),
(2)Corresponding to steam production in a boiler with typical refinery fuels.
FCC flue gas FCC flue gas to amine absorber SOx < 10 mg/Nm 3 NOx < 200 mg/Nm3 Electrofilter Catalytic DeNOx scrubber DeSOx washing section NH4OH NaOH
To waste water treatment
250 °C 250 °C 250 °C 50 °C
Figure 3
Wet scrubber technology.
Dry DeSOx reactor Sodium bicarbonate (NaHCO3) Low pressure steam Quench tower (HiCapt+TM unit) Heat recovery steam generator FCC flue gas FCC flue gas to amine absorber SOx < 10 mg/Nm3 NOx < 200 mg/Nm3 Electrofilter Catalytic DeNOx scrubber NH4OH 250 °C 200 °C 200 °C 200 °C 200 °C 50 °C Figure 4
(sodium bicarbonate NaHCO3) and the DeSOxscrubber
dry reactor. The gas treatment requires a cyclone to pro-tect the electrofilter. After the electrofilter, the DeNOx
scrubber works at 200°C adding NH4OH. This
technol-ogy works at 200°C and it is necessary to reduce the tem-perature from 250°C to 200°C before the dry DeSOx
reactor. Heat recovery on FCC flue gas can be imple-mented to recover heat from 250°C to 200°C. 6.3 t/h of Low Pressure (LP) steam can be generated. In the case of dry scrubber, the quench tower at the amine capture section is required to cool down the flue gas from 200°C to 50°C. This technology is considered more complex than the wet scrubber solution.
3.2 Impact of Pre-Treatment on CO2Capture
The design of the amine unit is independent of the DeSOx/DeNOxtechnology. The gas composition before
DeSOx/DeNOxunit implies that it is undersaturated at
50°C and requires make-up water to reach a neutral water balance in the process battery limits.
For a wet scrubber technology, the make-up water comes from the DeSOxwashing tower. In this case, the
flue gas could be injected directly at the bottom of the absorber.
For a dry scrubber technology, a quench tower is required before the absorber, to decrease the tempera-ture from 200°C to 50°C. The water saturation occurs in this equipment and the make-up is added to the water cooling loop directly.
3.3 Utilities for Flue Gas Pre-Treatment and CO2Capture
The list of utilities used for pre-treatment and CO2
cap-ture and compression is indicated inTable 4.
The main contributors of HiCapt+TMoperating cost are low pressure steam (3 GJ/t of captured CO2),
elec-tricity and cooling water.
3.4 CO2Balance of FCC Unit with HiCapt+TMProcess
As for the reference case, a simplified CO2balance has
been performed for FCC unit but at that time a more severe flue gas post treatment and the CO2capture on
flue gas were considered.
This CO2 balance has been estimated to
14.1 t CO2eq/h that is to say a reduction of 74% of
CO2emissions of the reference case.
As an FCC unit represents around 20% of refinery total CO2 emissions, HiCapt+TM association with an
FCC unit will remove more than 14% the refinery emis-sions and therefore much more than the required target of 10% as presented in the introduction.
Nevertheless, the cost associated with this significant GHG emission reduction has to be evaluated.
3.5 Economical Evaluation of CO2Capture with
HiCapt+TMProcess
The following section presents investment and operating cost estimates considering the wet scrubber technology for DeSOx/DeNOx.
3.5.1 Investment Cost Estimation
ISBL (InSide Battery Limit) cost of FCC unit has been estimated without and with CO2 capture on flue gas.
Results are presented inTable 5.
3.5.2 Operating Cost Estimation
HiCapt+TM shows energy consumption between 3.1 to 3.3 GJ to reduce CO2emissions by one ton. This places
HiCapt+TM among the most currently effective process technologies. A techno-economic evaluation of HiCapt+TMcompared to 30 wt% MEA process shows a reduction of around 15% in the cost of CO2captured [1].
Operating cost of an FCC unit has been estimated with and without the CO2 capture system on flue gas.
Operating cost includes utilities, chemicals and catalyst
TABLE 4
Chemicals and utilities balance for HiCapt+TMprocess Caustic soda
Sodium bicarbonate (for dry scrubber case only) Ammonia aqueous MEA Anti-oxidation additive Electricity LP steam Cooling water TABLE 5 ISBL cost FCC unit without CO2capture FCC unit with CO2capture
ISBL (M$) Base Base9 1.25
costs. Results are presented inTable 6. A penalty at 751/t of CO2 avoided must be compare with the cost of CO2
avoided in a refinery. In a recent study [4], the cost of CO2
capture lies in the range of 40-2631/t CO2-refinery-avoided.
Process integration between the capture process and the refinery is a key point to reduce costs, for example using excess heat or combined with heat pumps.
As presented in CO2balance, one of the main
contrib-utors to CO2in FCCU is the compressors and especially
the wet gas compressor. In order to go further in FCC CO2reduction, it is therefore interesting to investigate
and evaluate solutions to reduce utilities required for this compressor.
3.6 Impact of Wet Gas Compressor Driver
Generally, wet gas compressors are driven by condens-ing steam turbines or electric motors as in the reference
case considered previously. In condensing steam tur-bines, exhaust steam is in a partially condensed state (vapor fraction near 90%) and at a pressure well below atmospheric. Exhaust steam is then condensed with water (Fig. 5).
When steam is preferred to drive the wet gas compres-sor and when HiCapt+TMprocess is used for CO2
cap-ture, it is interesting to use a back-pressure steam turbine instead of a condensing steam turbine. The back-pressure steam turbine will consume more high pressure steam but low pressure steam at turbine outlet can be used directly in HiCapt+TM process for amine regeneration (Fig. 6).
The back-pressure steam turbine has the advantage to reduce the consumption of the cooling water of the pro-cess. A water condenser for vacuum steam condensation is no more needed. The flow rate of cooling water to con-dense vacuum steam is always very high.
The variation of operating cost and GHG emissions for the system “WGC + amine regeneration” is indi-cated inTable 7compared to a total condensing steam turbine.
The back-pressure turbine is therefore a relevant solution to limit CO2 emissions if there is a specific
need of LP steam as it is when amine capture is implemented.
High pressure steam 345 °C 43 bar abs WGC (1st stage) Total condensing steam turbine
Gas inlet Gas outlet
Water condenser Condensate 52 °C 0.14 bar abs WGC (2nd stage) Figure 5
Wet gas compressor driven by a condensing steam turbine. TABLE 6 Operating cost FCC unit without CO2capture FCC unit with CO2 capture Operating cost Base+ CO2penalty
of 75 $/t CO2avoided
CONCLUSIONS
The presented work enables to conclude that HiCapt+TMprocess is a relevant technology to manage CO2in FCC flue gas. In a technical point of view, FCC
Flue gas can be treated in HiCapt+TMprocess because HiCapt+TM inlet specifications can be easily reached. Based on a representative industrial case, it was evalu-ated that 74% of CO2emitted in FCC can be captured
and this corresponds to a reduction of more than 14% of the total CO2emitted in the refinery.
In an economical point of view, an amine capture unit leads to an additional cost estimated at around 25% which is significant but relatively limited. The impact on operating cost is fully in accordance with the one for power plant for which HiCapt+TM process was developed. As amine capture requires LP steam, back pressure turbine for wet gas compressor is an effective option which leads to additional CO2gains. In
conclu-sion, HiCapt+TMprocess is therefore a possible solution to reduce CO2 emissions for refining processes and
especially for FCC.
TABLE 7
Comparison of operating cost and GHG emissions for total condensing and back-pressure steam turbine
WGC driver type Total condensing steam turbine Back-pressure steam turbine (HP? LP steam)
HP steam for WGC driver Base Base + 41 t/h
Cooling water for WGC driver Base 0
LP steam for amine regeneration Base Base – 87 t/h
Operating cost(1) Base Base – 4.8 M$/year
GHG emissions(2) Base Base – 7.3 t CO
2eq/h (1) Considering following costs: HP steam = 22 $/t, LP steam = 15 $/t, Cooling water = 0.08 $/m3;
(2)
Considering following GHG emission factors: HP steam = 221 kg CO2eq/t, LP steam = 183 kg CO2eq/t, Cooling water = 0.188 kg CO2eq/m 3
.
Back-pressure steam turbine
High pressure steam 345 °C
43 bar abs WGC
(1st stage)
Gas inlet Gas outlet
Low pressure steam 141 °C
3.7 bar abs WGC
(2nd stage)
Figure 6
Wet gas compressor driven by a back-pressure steam turbine (HP? LP steam).
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Manuscript accepted in November 2013 Published online in April 2014
CopyrightÓ 2014 IFP Energies nouvelles
